<Page>
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                                 UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549

                              -------------------

                                   FORM 10-Q

<Table>
<S>              <C>
/X/              QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                 SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD
                 ENDED SEPTEMBER 30, 2001

                                     OR

/ /              TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                 SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD
                 FROM TO

                       COMMISSION FILE NUMBER: 0-6910
</Table>

                               -----------------

                               TEL OFFSHORE TRUST
             (Exact Name of Registrant as Specified in its Charter)

<Table>
<S>                                            <C>
                    TEXAS                                        76-6004064
           (State of Incorporation,                           I.R.S. Employer
               or Organization)                             Identification No.)

         JPMORGAN CHASE BANK, TRUSTEE
         INSTITUTIONAL TRUST SERVICES
                  700 LAVACA                                       78701
                AUSTIN, TEXAS                                    (Zip Code)
            (Address of Principal
              Executive Offices)
</Table>

       Registrant's Telephone Number, Including Area Code: (512) 479-2562

    Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports) and (2) has been subject to such
filing requirements for the past 90 days.  Yes X  No _

    Indicate the number of shares outstanding of each of the registrant's
classes of common stock, as of the latest practicable date.

    As of November 5, 2001--4,751,510 Units of Beneficial Interest in TEL
Offshore Trust.

--------------------------------------------------------------------------------
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<Page>
                   NOTE REGARDING FORWARD-LOOKING STATEMENTS

    This Form 10-Q includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. All statements other than
statements of historical facts included in this Form 10-Q are forward-looking
statements. Although the Working Interest Owners (as defined herein) have
advised the Trust that they believe that the expectations reflected in the
forward-looking statements contained herein are reasonable, no assurance can be
given that such expectations will prove to have been correct. Important factors
that could cause actual results to differ materially from expectations
("Cautionary Statements") are disclosed in this Form 10-Q, including without
limitation in conjunction with the forward-looking statements included in this
Form 10-Q. All subsequent written and oral forward-looking statements
attributable to the Trust or persons acting on its behalf are expressly
qualified in their entirety by the Cautionary Statements.

                                       i
<Page>
                         PART I--FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

               STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

<Table>
<Caption>
                                                              SEPTEMBER 30,   DECEMBER 31,
                                                                  2001            2000
                                                              -------------   -------------
                                                               (UNAUDITED)
<S>                                                           <C>             <C>
ASSETS
Cash and cash equivalents...................................   $2,112,551      $3,922,089
Net overriding royalty interest in producing oil and gas
  properties, net of accumulated amortization of $28,038,700
  and $27,998,574, respectively.............................      228,955         269,081
                                                               ----------      ----------
Total assets................................................   $2,341,506      $4,191,170
                                                               ==========      ==========

LIABILITIES AND TRUST CORPUS
Distribution payable to Unit holders........................   $1,133,580      $2,804,605
Reserve for future Trust expenses...........................      978,971       1,117,484
Commitments and contingencies (Note 7)
Trust corpus (4,751,510 Units of beneficial interest
  authorized and outstanding)...............................      228,955         269,081
                                                               ----------      ----------
Total liabilities and Trust corpus..........................   $2,341,506      $4,191,170
                                                               ==========      ==========
</Table>

                       STATEMENTS OF DISTRIBUTABLE INCOME
                                  (UNAUDITED)

<Table>
<Caption>
                                                THREE MONTHS ENDED          NINE MONTHS ENDED
                                                   SEPTEMBER 30,              SEPTEMBER 30,
                                              -----------------------   --------------------------
                                                 2001         2000          2001           2000
                                              ----------   ----------   -------------   ----------
<S>                                           <C>          <C>          <C>             <C>
Royalty income..............................  $1,031,826   $1,987,518   $   3,991,769   $4,561,785
Interest income.............................      30,810       18,671          78,209       53,275
                                              ----------   ----------   -------------   ----------
                                               1,062,636    2,006,189       4,069,978    4,615,060
Decrease in reserve for future Trust
expenses....................................           0            0         138,513      266,759
General and administrative expenses.........     (70,738)     (60,625)       (301,380)    (221,931)
Other.......................................     141,682           --         141,682           --
                                              ----------   ----------   -------------   ----------
Distributable income........................  $1,133,580   $1,945,564   $   4,048,896   $4,659,888
                                              ==========   ==========   =============   ==========
Distributions per Unit (4,751,510 Units)....  $  .238573   $  .409462   $     .852128   $  .980716
                                              ==========   ==========   =============   ==========
</Table>

   The accompanying notes are an integral part of these financial statements.

                                       1
<Page>
                     STATEMENTS OF CHANGES IN TRUST CORPUS
                                  (UNAUDITED)

<Table>
<Caption>
                                                THREE MONTHS ENDED           NINE MONTHS ENDED
                                                   SEPTEMBER 30,               SEPTEMBER 30,
                                             -------------------------   -------------------------
                                                2001          2000          2001          2000
                                             -----------   -----------   -----------   -----------
<S>                                          <C>           <C>           <C>           <C>
Trust corpus, beginning of period..........  $   241,144   $   329,216   $   269,081   $   367,768
Distributable income.......................    1,133,580     1,945,564     4,048,896     3,962,821
Distribution payable to Unit holders.......   (1,133,580)   (1,945,564)   (4,048,896)   (3,962,821)
Amortization of net overriding royalty
interest...................................      (12,189)      (26,107)      (40,126)      (64,659)
                                             -----------   -----------   -----------   -----------
Trust corpus, end of period................  $   228,955   $   303,109   $   228,955   $   303,109
                                             ===========   ===========   ===========   ===========
</Table>

   The accompanying notes are an integral part of these financial statements.

                                       2
<Page>
                               TEL OFFSHORE TRUST

                         NOTES TO FINANCIAL STATEMENTS

                                  (UNAUDITED)

NOTE 1--TRUST ORGANIZATION

    Tenneco Offshore Company, Inc. ("Tenneco Offshore") created the TEL Offshore
Trust ("Trust") effective January 1, 1983, pursuant to the Plan of Dissolution
("Plan") approved by Tenneco Offshore's stockholders on December 22, 1982. In
accordance with the Plan, the TEL Offshore Trust Partnership ("Partnership") was
formed in which the Trust owns a 99.99% interest and Tenneco Oil Company
("Tenneco") initially owned a .01% interest. In general, the Plan was effected
by transferring an overriding royalty interest ("Royalty") equivalent to a 25%
net profits interest in the oil and gas properties (the "Royalty Properties") of
Tenneco Exploration, Ltd. ("Exploration I") located offshore Louisiana to the
Partnership and issuing certificates evidencing units of beneficial interest in
the Trust ("Units") in liquidation and cancellation of Tenneco Offshore's common
stock.

    On October 31, 1986, Exploration I was dissolved and the oil and gas
properties of Exploration I were distributed to Tenneco subject to the Royalty.
Tenneco, who was then serving as the Managing General Partner of the
Partnership, assumed the obligations of Exploration I, including its obligations
under the instrument conveying the Royalty to the Partnership (the
"Conveyance"). The dissolution of Exploration I had no impact on future cash
distributions to Unit holders.

    On November 18, 1988, Chevron U.S.A. Inc. ("Chevron") acquired most of the
Gulf of Mexico offshore oil and gas properties of Tenneco, including all the
Royalty Properties. As a result of the acquisition, Chevron replaced Tenneco as
the Working Interest Owner and Managing General Partner of the Partnership.
Chevron also assumed Tenneco's obligations under the Conveyance.

    On October 30, 1992, PennzEnergy Company ("PennzEnergy") acquired certain
oil and gas producing properties from Chevron, including four of the Royalty
Properties. The four Royalty Properties acquired by PennzEnergy were East
Cameron 354, Eugene Island 348, Eugene Island 367 and Eugene Island 208. As a
result of such acquisition, PennzEnergy replaced Chevron as the Working Interest
Owner of such properties on October 30, 1992. PennzEnergy also assumed Chevron's
obligations under the Conveyance with respect to such properties.

    On December 1, 1994, Texaco Exploration and Production Inc. ("Texaco")
acquired two of the Royalty Properties from Chevron. The Royalty Properties
acquired by Texaco were West Cameron 643 and East Cameron 371/381. As a result
of such acquisitions, Texaco replaced Chevron as the Working Interest Owner of
such properties on December 1, 1994. Texaco also assumed Chevron's obligations
under the Conveyance with respect to such properties.

    On October 1, 1995, SONAT Exploration Company ("SONAT") acquired the East
Cameron 354 property from PennzEnergy. In addition, on October 1, 1995, Amoco
Production Company ("Amoco") acquired the Eugene Island 367 property from
PennzEnergy. As a result of such acquisitions, SONAT and Amoco replaced
PennzEnergy as the Working Interest Owners of the East Cameron 354 and Eugene
Island 367 properties, respectively, on October 1, 1995 and also assumed
PennzEnergy's obligations under the Conveyance with respect to such properties.

                                       3
<Page>
                               TEL OFFSHORE TRUST

                   NOTES TO FINANCIAL STATEMENTS (CONTINUED)

                                  (UNAUDITED)

NOTE 1--TRUST ORGANIZATION (CONTINUED)
    Effective January 1, 1998, Energy Resource Technology, Inc. ("Energy")
acquired the East Cameron 354 property from SONAT. As a result of such
acquisition, Energy replaced SONAT as the Working Interest Owner of the East
Cameron 354 property effective January 1, 1998, and also assumed SONAT's
obligations under the Conveyance with respect to such property. In
October 1998, Amerada Hess Corporation ("Amerada") acquired the East Cameron 354
property from Energy effective January 1, 1998. As a result of such acquisition,
Amerada replaced Energy as the Working Interest Owner of the East Cameron 354
property effective January 1, 1998, and also assumed Energy's obligations under
the Conveyance with respect to such property.

    Effective January 1, 2000 PennzEnergy and Devon Energy Corporation (Nevada)
merged into Devon Energy Production Company L.P. ("Devon"). As a result of such
merger, Devon replaced PennzEnergy as the Working Interest Owner of Eugene
Island 348 and Eugene Island 208 properties effective January 1, 2000, and also
assumed PennzEnergy's obligations under the Conveyance with respect to such
properties.

    All of the Royalty Properties continue to be subject to the Royalty, and it
is anticipated that the Trust and the Partnership, in general, will continue to
operate as if the above-described sales of the Royalty Properties had not
occurred.

    Unless the context in which such terms are used indicates otherwise, in
these Notes the terms "Working Interest Owner" and "Working Interest Owners"
generally refer to the owner or owners of the Royalty Properties (Exploration I
through October 31, 1986; Tenneco for periods from October 31, 1986 until
November 18, 1988; Chevron with respect to all Royalty Properties for periods
from November 18, 1988 until October 30, 1992, and with respect to all Royalty
Properties except East Cameron 354, Eugene Island 348, Eugene Island 367 and
Eugene Island 208 for periods from October 30, 1992 until December 1, 1994, and
with respect to the same properties except West Cameron 643 and East Cameron
371/381 thereafter; PennzEnergy with respect to East Cameron 354, Eugene Island
348, Eugene Island 367 and Eugene Island 208 for periods from October 30, 1992
until October 1, 1995, and with respect to Eugene Island 348 and Eugene Island
208 until January 1, 2000; Texaco with respect to West Cameron 643 and East
Cameron 371/381 for periods beginning on or after December 1, 1994; SONAT with
respect to East Cameron 354 for periods beginning on or after October 1, 1995;
and Amoco with respect to Eugene Island 367 for periods beginning on or after
October 1, 1995; and Amerada with respect to East Cameron 354 for periods
beginning on or after January 1, 1998; and Devon with respect to Eugene Island
348 and Eugene Island 208 for periods beginning on or after January 1, 2000).

NOTE 2--BASIS OF ACCOUNTING

    The accompanying unaudited financial information has been prepared by
JPMorgan Chase Bank ("Corporate Trustee"). JPMorgan Chase Bank was formerly
known as The Chase Manhattan Bank, which was formerly known as Chase Bank of
Texas, National Association, which was formerly known as Texas Commerce Bank
National Association, in accordance with the instructions to Form 10-Q and does
not

                                       4
<Page>
                               TEL OFFSHORE TRUST

                   NOTES TO FINANCIAL STATEMENTS (CONTINUED)

                                  (UNAUDITED)

NOTE 2--BASIS OF ACCOUNTING (CONTINUED)
include all of the information required by generally accepted accounting
principles for complete financial statements. The Corporate Trustee and the
individual trustees (collectively, the "Trustees") believe that the disclosures
are adequate to make the information presented not misleading. The information
furnished reflects all adjustments which are, in the opinion of the Trustees,
necessary for a fair presentation of the results for the interim periods
presented. The financial information should be read in conjunction with the
financial statements and notes thereto included in the Trust's Annual Report on
Form 10-K for the year ended December 31, 2000.

    The financial statements of the Trust are prepared on the following basis:

    (a) Royalty income is recorded when received by the Corporate Trustee on the
       last business day of each calendar quarter; and

    (b) Trust general and administrative expenses are recorded when paid, except
       for the cash reserved for future general and administrative expenses, as
       discussed in Note 6.

    This manner of reporting income and expenses is considered to be the most
meaningful because the quarterly distributions to Unit holders are based on net
cash receipts received from the Working Interest Owners. The financial
statements of the Trust differ from financial statements prepared in accordance
with generally accepted accounting principles, because, under such principles,
Royalty income and Trust general and administrative expenses for a quarter would
be recognized on an accrual basis. In addition, amortization of the overriding
royalty interest, which is calculated on a units-of-production basis, is charged
directly to Trust corpus since such amount does not affect distributable income.

    Cash and cash equivalents include all highly liquid, short-term investments
with original maturities of three months or less.

    The Trust reviews net overriding royalty interest in oil and gas properties
for possible impairment whenever events or circumstances indicate the carrying
amount of the asset may not be recoverable. If there is an indication of
impairment, the Trust prepares an estimate of future cash flows (undiscounted
and without interest charges) expected to result from the use of the asset and
its eventual disposition. If these cash flows are less than the carrying amount
of the asset, an impairment loss is recognized to write down the asset to its
estimated fair value. Preparation of estimated expected future cash flows is
inherently subjective and is based on management's best estimate of assumptions
concerning expected future conditions. There were no write downs taken in the
periods presented.

    The preparation of financial statements requires the Trustees to make use of
estimates and assumptions that affect amounts reported in the financial
statements as well as certain discounts. Actual results could differ from those
estimates.

    The amount of cash distributions by the Trust is dependent on, among other
things, the sales prices for oil and gas produced from the Royalty Properties
and the quantities of oil and gas sold. It should be noted

                                       5
<Page>
                               TEL OFFSHORE TRUST

                   NOTES TO FINANCIAL STATEMENTS (CONTINUED)

                                  (UNAUDITED)

NOTE 2--BASIS OF ACCOUNTING (CONTINUED)
that substantial uncertainties exist with regard to future oil and gas prices,
which are subject to material fluctuations due to changes in production levels
and pricing and other actions taken by major petroleum producing nations, as
well as the regional supply and demand for gas, weather, industrial growth,
conservation measures, competition and other variables. The Trust does not enter
into any hedging transactions on future production. Accordingly, the Statement
of Financial Accounting Standards No. 133, "Accounting of Derivative Instruments
and Hedging Activities," as amended, that was effective January 1, 2001, has not
had an impact on the financial statements.

NOTE 3--NET OVERRIDING ROYALTY INTEREST

    The Royalty entitles the Trust to its share (99.99%) of 25% of the Net
Proceeds attributable to the Royalty Properties. The Conveyance, dated
January 1, 1983, provides that the Working Interest Owners will calculate, for
each period of three months commencing the first day of February, May, August
and November, an amount equal to 25% of the Net Proceeds from their oil and gas
properties for the period. Generally, Net Proceeds are the amounts received by
the Working Interest Owners from the sale of minerals from the Royalty
Properties less operating and capital costs incurred, management fees and
expense reimbursements owing to the Managing General Partner of the Partnership,
applicable taxes other than income taxes, and a special cost reserve. The
Special Cost Reserve Account is established for the future costs to be incurred
to plug and abandon wells, dismantle and remove platforms, pipelines and other
production facilities, and for the estimated amount of future capital
expenditures on the Royalty Properties. Net Proceeds do not include amounts
received by the Working Interest Owners as advance gas payments, "take-or-pay"
payments or similar payments unless and until such payments are extinguished or
repaid through the future delivery of gas.

NOTE 4--DISTRIBUTIONS TO UNIT HOLDERS

    In accordance with the provisions of the Trust Agreement, generally all Net
Proceeds received by the Trust, net of Trust general and administrative expenses
and any cash reserves established for the payment of contingent or future
obligations of the Trust, are distributed currently to the Unit holders. The
amounts distributed are determined on a quarterly basis and are payable to Unit
holders of record as of the last business day of each calendar quarter. However,
cash distributions are made in January, April, July and October and include
interest earned from the quarterly record date to the date of distribution.

NOTE 5--SPECIAL COST ESCROW ACCOUNT

    The Conveyance provides for the reserve of funds for estimated future
"Special Costs" of plugging and abandoning wells, dismantling platforms and
other costs of abandoning the Royalty Properties, as well as for the estimated
amount of future drilling projects and other capital expenditures on the Royal
Properties. As provided in the Conveyance, the amount of funds to be reserved is
determined based on

                                       6
<Page>
                               TEL OFFSHORE TRUST

                   NOTES TO FINANCIAL STATEMENTS (CONTINUED)

                                  (UNAUDITED)

NOTE 5--SPECIAL COST ESCROW ACCOUNT (CONTINUED)
certain factors, including estimates of aggregate future production costs,
aggregate future Special Costs, aggregate future net revenues and actual current
net proceeds. Deposits into this account reduce current distributions and are
placed in an escrow account and invested in short-term certificates of deposit.
Such account is herein referred to as the "Special Cost Escrow Account." The
Trust's share of interest generated from the Special Cost Escrow Account serves
to reduce the Trust's share of allocated production costs. Special Cost Escrow
funds will generally be utilized to pay Special Costs to the extent there are
not adequate current net proceeds to pay such costs. Special Costs that have
been paid are no longer included in the Special Cost Escrow calculation.
Deposits to the Special Cost Escrow Account will generally be made when the
balance in the Special Cost Escrow Account is less than 125% of future Special
Costs and there is a Net Revenues Shortfall (a calculation of the excess of
estimated future costs over estimated future net revenues pursuant to a formula
contained in the Conveyance). When there is not a Net Revenues Shortfall,
amounts in the Special Cost Escrow Account will generally be released, to the
extent that Special Costs have been incurred. Amounts in the Special Cost Escrow
Account generally will also be released when the balance in such account exceeds
125% of future Special Costs. In the first nine months of 2000, there was a net
deposit of funds into the Special Cost Escrow Account. The Trust's share of the
funds deposited was approximately $778,327. The deposit was primarily a result
of an increase in the Working Interest Owners' current estimate of projected
capital expenditures of the Royalty Properties. In the first nine months of
2001, there was a net deposit of funds into the Special Escrow Account. The
Trust's share of the funds deposited was approximately $315,509. This deposit
was also primarily a result of an increase in the Working Interest Owner's
current estimate of projected capital expenditures of the Royalty Properties. As
of September 30, 2001, approximately $5,712,345 remained in the Special Cost
Escrow Account.

    Chevron, in its capacity as Managing General Partner, has advised the Trust
that additional deposits to the Special Cost Escrow Account may be required in
future periods in connection with other production costs, other abandonment
costs, other capital expenditures and changes in the estimates and factors
described above. Such deposits could result in a significant reduction in
Royalty income in the periods in which such deposits are made, including the
possibility that no Royalty income would be received in such periods.

NOTE 6--EXPENSE RESERVE

    In the first quarter of 1998, the Trust determined that the Trust's cash
reserve was currently sufficient to provide for future administrative expenses
in connection with the winding up of the Trust. The Trust determined that a cash
reserve equal to three times the average expenses of the Trust during each of
the past three years was sufficient at this time to provide for future
administrative expenses in connection with the winding up of the Trust. The
reserve amount for 2000 was $1,117,484. The excess amount in the reserve of
$266,759 was distributed to Unit holders in the first quarter of 2000. The
reserve amount for 2001 is

                                       7
<Page>
                               TEL OFFSHORE TRUST

                   NOTES TO FINANCIAL STATEMENTS (CONTINUED)

                                  (UNAUDITED)

NOTE 6--EXPENSE RESERVE (CONTINUED)
$978,971. The excess amount in the reserve of $138,513 was distributed to
Unitholders in the first quarter of 2001.

NOTE 7--COMMITMENTS AND CONTINGENCIES

    During 1994, the Working Interest Owner on the Eugene Island 348 property
settled a gas imbalance on that property for approximately $2,696,000. The
Trust's share of this settlement amount was approximately $674,000, of which
approximately $500,853 has been recovered from the Trust by Devon (as successor
of PennzEnergy) through the third quarter of 2001. The remainder will be subject
to recovery from the Trust during future periods in accordance with the
Conveyance. The Working Interest Owner on the Eugene Island 348 property has
advised the Trust that future Royalty income attributable to all of the Royalty
Properties owned by this Working Interest Owner will be used to offset the
Trust's share of such settlement amounts. Based on current production, prices
and expenses for the Royalty Properties owned by this Working Interest Owner, it
is estimated that Royalty income attributable to such properties will be
retained by this Working Interest Owner for the remaining life of the Trust. The
Trust does not anticipate that retention of such Royalty income by this Working
Interest Owner will have a material effect on the Trust's Royalty income as a
whole.

    The Working Interest Owners have advised the Trust that, although they
believe that they are in general compliance with applicable health, safety and
environmental laws and regulations that have taken effect at the federal, state
and local levels, costs may be incurred to comply with current and proposed
environmental legislation which could result in increased operating expenses on
the Royalty Properties.

                                       8
<Page>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
        OF OPERATIONS.

FINANCIAL REVIEW

THREE MONTHS ENDED SEPTEMBER 30, 2001 AND 2000

    Distributions to the Unit holders for the three months ended September 30,
2001 amounted to $1,133,580 or $.238573 per Unit as compared to $1,945,564 or
$.409462 per Unit for the same period in 2000. The decrease in distribution
income for the third quarter of 2001 was primarily due to decreased oil and gas
prices, offset by production volume declines, as described below.

    Gas revenues recorded by the Working Interest Owners on the Trust Properties
decreased 53% to $1,521,066 in the third quarter of 2001 from $3,262,120 in the
third quarter of 2000 due primarily to a 16% decrease in gas volumes to 378,833
Mcf in the third quarter of 2001 from 426,363 Mcf in the third quarter of 2000
and a decrease in the average price received. The lower gas volumes were
primarily due to decreased production on West Cameron 643 due to a shut in and
temporary abandonment of the B-8 well and the normalized production after second
quarter adjustments on Eugene Island 339. These lower volumes were partially
offset by increased production on the Ship Shoal 182/183 E10 well. The average
price received for natural gas decreased 7% to $3.71 per Mcf in the third
quarter of 2001 from $4.00 per Mcf in the third quarter of 2000.

    Crude oil revenues recorded by the Working Interest Owners decreased 21% to
$4,345,468 in the third quarter of 2001 from $5,490,663 in the third quarter of
2000. Oil volumes during the third quarter of 2001 totaled 164,624 barrels,
compared to 196,673 barrels of oil produced in the third quarter of 2000.

    The Trust's share of capital expenditures increased by $503,415 in the third
quarter of 2001, to $858,609, as compared to the third quarter of 2000. The
lower capital expenditures in the third quarter of 2001 were due primarily to
normalization after the second quarter C-4 and C-12 major rig workovers on Ship
Shoal 182/183, offset by control panel upgrades on Eugene Island 339 and West
Cameron 643B mobilization/demobilization.

    For the third quarter of 2001, the Trust had undistributed net income of
$28,535. Undistributed net income represents positive Net Proceeds, generated
during the respective period, that were applied to an existing loss
carryforward. Undistributed net loss represents negative Net Proceeds generated
during the respective period. An undistributed net loss is carried forward and
offset, in future periods, by positive Net Proceeds earned by the related
Working Interest Owner(s). The undistributed net income for the third quarter of
2001 was primarily related to the loss carryforward referred to above on the
Eugene Island 348 property.

    In the third quarter of 2001, there was a net release of funds from the
Special Cost Escrow Account. The Trust's share of the funds released was
approximately $83,867, compared to a net deposit of funds into the Special Cost
Escrow Account of $131,239.02 net to the Trust in the third quarter of 2000. The
Special Cost Escrow is set aside for estimated abandonment costs and future
capital expenditures as provided for in the Conveyance. For additional
information relating to the Special Cost Escrow see "Special Cost Escrow
Account" below.

                                       9
<Page>
NINE MONTHS ENDED SEPTEMBER 30, 2001 AND 2000

    Distributions to Unit holders for the nine months ended September 30, 2001
amounted to $4,048,896 or $.852128 per Unit, as compared to $4,659,888 or
$.980716 per Unit for the same period in 2000. The decrease in distributable
income for the first nine months of 2001 was primarily due to decreased oil and
gas prices, offset by production volume declines, as described below.

    Gas revenues decreased $722,965, or 8%, to $8,656,305 in the first nine
months of 2001 from $9,379,270 in the first nine months of 2000, primarily due
to a 49% increase in the average price received for natural gas to $5.88 per Mcf
in the first nine months of 2001 from $2.98 per Mcf in the first nine months of
2000. The increase in average price was partially offset by a 52% decrease in
gas volumes to 1,509,357 Mcf in the first nine months of 2001 from 3,196,563 Mcf
in the first nine months of 2000.

    Crude oil and condensate revenues decreased $2,915,422, or 17%, to
$14,118,523 in the first nine months of 2001 as compared to $17,033,945 in the
same period in 2000, primarily due to a 23% decrease in the crude oil and
condensate volume from the first nine months of 2000 to the first nine months of
2001. The decrease in crude oil and condensate volumes was partially offset by
an 8% increase in the average price of crude oil and condensate from $27.05 per
barrel in the first nine months of 2000 to $29.11 per barrel in the first nine
months of 2001.

    The Trust's share of capital expenditures increased by $495,349 in the first
nine months of 2001 as compared to the same period in 2000.

    In the first nine months of 2001, there was a net deposit of funds into the
Special Cost Escrow Account. The Trust's share of the funds deposited was
approximately $315,509 compared to a net deposit of funds into the Special Cost
Escrow Account of approximately $3,113,307 net to the Trust in the first nine
months of 2000.

RESERVE FOR FUTURE TRUST EXPENSES

    In accordance with the provisions of the Trust Agreement, generally all Net
Proceeds received by the Trust, net of Trust general and administrative expenses
and any cash reserves established for the payment of contingent or future
obligations of the Trust, are distributed currently to the Unit holders. In the
first quarter of 1998, the Trust determined that the Trust's cash reserve was
currently sufficient to provide for future administrative expenses in connection
with the winding up of the Trust. The Trust determined that a cash reserve equal
to three times the average expenses of the Trust during each of the past three
years was sufficient at this time to provide for future administrative expenses
in connection with the winding up of the Trust. The reserve amount for 2000 was
$1,117,484. The reserve amount for 2001 is $978,971. The excess amount in the
reserve of $138,513 was distributed to Unit holders in the first quarter of
2001.

OTHER

    The amount of cash distributed by the Trust is dependent on, among other
things, the sales prices and quantities of oil and gas produced from the Royalty
Properties. It should be noted that substantial uncertainties exist with regard
to future oil and gas prices, which are subject to material fluctuations due to
changes in production levels and pricing and other actions taken by major
petroleum producing nations, as well as the regional supply and demand for oil
and gas, weather, industrial growth, conservation measures, competition and
other variables.

                                       10
<Page>
OPERATIONAL REVIEW

THREE MONTHS ENDED SEPTEMBER 30, 2001 AND 2000

    VOLUMES AND DOLLAR AMOUNTS DISCUSSED BELOW REPRESENT AMOUNTS RECORDED BY THE
WORKING INTEREST OWNERS UNLESS OTHERWISE SPECIFIED.

    Ship Shoal 182/183 crude oil revenues decreased from $3,554,374 in the third
quarter of 2000 to $2,931,386 in the third quarter of 2001, primarily due to a
decrease in crude oil production from 125,797 barrels in the third quarter of
2000 to 110,195 barrels in the third quarter of 2001. The decrease in crude oil
production was due primarily to continued natural production declines of these
properties. The decrease in crude oil production was compounded by a decrease in
the average price of crude oil from $29.25 per barrel in the third quarter of
2000 to $26.60 per barrel in the third quarter of 2001. Gas revenues decreased
from $780,821 in the third quarter of 2000 to $275,843 in the third quarter of
2001, primarily due to a decrease in gas volumes from 202,322 Mcf in the third
quarter of 2000 to 99,770 Mcf in the third quarter of 2001. The decrease in gas
revenues was compounded by a decrease in the average natural gas sales price
from $3.86 per Mcf in the third quarter of 2000 to $2.76 per Mcf in the third
quarter of 2001. The decrease in gas volumes was primarily as a result of the
C-10 well going off production and the E-10 well watering out. The gas from Ship
Shoal 182/183 is committed to Dynegy Inc. ("Dynegy") at a calculated price based
on the monthly Inside FERC Tennessee-Louisiana Zone 1 Index. In addition, the
Working Interest Owner has advised the Trust that approximately 64,177 Mcf have
been overtaken by the Working Interest Owner from this property as of July 31,
2001. The Trust's share of this overtake position is approximately 16,044 Mcf.
Accordingly, gas revenues from this property may be decreased in future periods
while underproduced parties recoup their share of the gas imbalance. Chevron has
advised the Trust that sufficient gas reserves exist on Ship Shoal 182/183 for
underproduced parties to recoup their share of the gas imbalance on this
property. Capital expenditures increased to $331,498 in the third quarter of
2001 from $3,723 in the third quarter of 2000. This increase was primarily due
to major rig workovers on the C-4 and C-12 wells. Operating expenses increased
from $405,832 in the third quarter of 2000 to $422,610 for the same period in
2001.

    Eugene Island 339 crude oil revenues decreased from $1,597,975 in the third
quarter of 2000 to $1,197,013 in the third quarter of 2001, primarily due to a
decrease in crude oil production from 59,521 barrels in the third quarter of
2000 to 46,503 barrels in the third quarter of 2001. The decrease in crude oil
production was due primarily to continued natural production declines of these
properties. The decrease in crude oil production was compounded by a decrease in
the average price of crude oil from $26.85 per barrel in the third quarter of
2000 to $25.74 per barrel in the third quarter of 2001. Gas revenues decreased
to $104,531 in the third quarter of 2001 from $221,236 in the third quarter of
2000, primarily due a decrease in the average natural gas sales price from $3.92
per Mcf in the third quarter of 2000 to $2.71 in the third quarter of 2001. The
Working Interest Owner has advised the Trust that there is an overtake imbalance
position of approximately 5,281 Mcf on this property as of November 30, 2000.
The Trust's share of this overtake position is approximately 1,320 Mcf.
Accordingly, gas revenues from this property may be reduced in future periods
while underproduced parties recoup their share of the gas imbalance. Chevron has
advised the Trust that sufficient gas reserves exist on the Eugene Island 339
for underproduced parties to recoup their share of the gas imbalance on this
property. The gas from this property is currently committed to Dynegy at a
calculated price based on the monthly Inside FERC Tennessee-Louisiana Zone 1
Index. Capital expenditures decreased by $102,396 from the third quarter of 2001
as compared to the

                                       11
<Page>
third quarter of 2000. Operating expenses decreased by $48,082 from the third
quarter of 2001 as compared to the third quarter of 2000.

    West Cameron 643 gas revenues decreased from $1,407,829 in the third quarter
of 2000 to $577,825 in the third quarter of 2001, primarily due to a decrease in
gas volumes from 354,167 in the third quarter of 2000 to 145,705 in the third
quarter of 2001. The decrease in gas volumes was due primarily to the B-8 well
being shut in and temporarily abandoned, the A-10 well going off production and
the A-7 well watering out. The decrease in gas volumes was compounded by a
slight decrease in average natural gas sales price from $3.98 per Mcf in the
third quarter of 2000 to $3.97 in the third quarter of 2001. The gas from West
Cameron 643 is currently committed to Texaco Natural Gas Inc. ("TNGI"). TNGI is
a wholly owned affiliate of Texaco Exploration and Production Inc. ("TEPI").
TNGI purchases natural gas from TEPI and resells such gas to a variety of
third-party customers at a variety of downstream delivery points. The prices
that TNGI pays TEPI for the gas production is based on the actual sale prices
that TNGI receives from its third-party customers less the actual transportation
costs, if any, that TNGI pays to a transporting pipeline. TEPI's proceeds are
based on 100% of the actual resale price of the gas, less actual transportation
costs. The Working Interest Owner has advised the Trust that approximately
22,853 Mcf have been overtaken by the Working Interest Owner from this property
as of November 30, 2000. The Trust's share of this overtake position is
approximately 5,713 Mcf. Accordingly, gas revenues from this property may be
reduced in future periods while underproduced parties recover their share of the
gas imbalance. Operating expenses decreased slightly in the third quarter of
2001 as compared to the same period in 2000. Capital expenditures increased by
$252,715 in the third quarter of 2001 as compared to the same period in 2000,
primarily due to costs associated with the mobilization/demobilization of WC643B
in the third quarter of 2001.

    East Cameron 371/381 crude oil revenues decreased from $179,079 in the third
quarter of 2000 to $44,130 in the third quarter of 2001, primarily due to a
decrease in crude oil production from 5,901 barrels in the third quarter of 2000
to 1,645 barrels in the third quarter of 2001. Gas revenues decreased from
$479,405 in the third quarter of 2000 to $140,251 in the third quarter of 2001,
primarily due to a decrease in gas volumes from 130,516 Mcf in the third quarter
of 2000 to 33,656 Mcf in the third quarter of 2001. The decrease in gas revenues
was partially offset by an increase in the average natural gas sales price from
$3.67 per Mcf in the third quarter of 2000 to $4.17 per Mcf in the third quarter
of 2001. The gas from East Cameron 371/381 is currently committed to TNGI on
terms similar to gas committed to West Cameron 643. Operating expenses did not
change significantly. Capital expenses increased $13,607 due to capital expense
audit adjustment credits recognized in the third quarter of 2001.

NINE MONTHS ENDED SEPTEMBER 30, 2001 AND 2000

    VOLUMES AND DOLLAR AMOUNTS DISCUSSED BELOW REPRESENT AMOUNTS RECORDED BY THE
WORKING INTEREST OWNERS UNLESS OTHERWISE SPECIFIED.

    Ship Shoal 182/183 crude oil revenues decreased from $11,014,759 in the
first nine months of 2000 to $9,202,980 in the first nine months of 2001,
primarily due to a decrease in crude oil production from 402,940 barrels in the
nine months of 2000 to 317,840 barrels in the first nine months of 2001. The
decrease in crude oil production was due primarily to continued natural
production declines of these properties. The decrease in crude oil production
was partially offset by an increase in the average price of crude oil from
$27.34 per barrel in the first nine months of 2000 to $28.95 per barrel in the
first nine months of 2001. Gas revenues decreased from $2,236,081 in the first
nine months of 2000 to $1,903,018 in the first nine

                                       12
<Page>
months of 2001, primarily due to a significant decrease in volumes that was
partially offset by a substantial increase in the average natural gas sales
price from $2.92 per Mcf in the first nine months of 2000 to $5.73 per Mcf in
the first nine months of 2001. The decrease in gas volumes from 766,044 Mcf in
the first nine months of 2000 to 332,049 Mcf in the first nine months of 2001
was primarily a result of the C-10 well going off production and the E-10 and
B-15 wells watering out. Capital expenditures increased from $160,900 in the
first nine months of 2000 to $1,186,642 in the same period of 2001 primarily due
to major rig workovers on the C-4 and C-12 wells in the second quarter of 2001.
Operating expenses decreased from $1,302,472 for the first nine months of 2000
to $1,129,677 for the first nine months of 2001.

    Eugene Island 339 crude oil revenues decreased from $4,835,249 in the first
nine months of 2000 to $4,153,560 in the first nine months of 2001, primarily
due to a decrease in crude oil production from 185,496 barrels in the first nine
months of 2000 to 142,002 barrels in the first nine months of 2001. The decrease
in crude oil production was due primarily to continued natural production
declines of these properties. The decrease in crude oil production was partially
offset by an increase in the average price of crude oil from $26.07 per barrel
in the first nine months of 2000 to $29.25 per barrel in the first nine months
of 2001. Gas revenues decreased to $733,133 in the first nine months of 2001
from $762,231 in the first nine months of 2000, primarily due to a significant
decrease from 263,00 Mcf in the first nine months of 2000 to 123,766 Mcf in the
first nine months of 2001. This decrease in production was offset by an increase
in the average natural gas sales price from $2.90 per Mcf in the first nine
months of 2000 to $5.92 per Mcf in the first nine months of 2001. Operating
expenses decreased from $902,045 for the nine months of 2000 to $830,467 for the
first nine months of 2001. Capital expenditures decreased from $1,001,294 in the
first nine months of 2000 to $312,131 in the first nine months of 2001. This
decrease was due to A-7 and B-18 sidetracks and platform facility improvements
done in 2000.

    West Cameron 643 gas revenues decreased from $3,868,070 in the first nine
months of 2000 to $3,453,878 in the first nine months of 2001, primarily due to
a decrease in natural gas volumes from 1,297,350 Mcf in the first nine months of
2000 to 596,662 Mcf in the first nine months of 2001. This decrease in
production was offset by an increase in average natural gas sales price from
$2.98 per Mcf in the first nine months of 2000 to $5.79 per Mcf in the first
nine months of 2001. The decrease in gas volumes was due to the B-8 well being
shut in and temporarily abandoned, the A-10 well going off production, and the
A-7 well watering out. Operating expenses for the first nine months of 2001
decreased by $6,406 compared to the first nine months of 2000. Capital
expenditures increased from $109,012 in the first nine months of 2000 to
$376,838 in the first nine months of 2001, primarily due to costs associated
with the mobilization of WC643B in the third quarter of 2001.

    East Cameron 371/381 crude oil revenues decreased from $713,920 in the first
nine months of 2000 to $148,520 in the first nine months of 2001, primarily due
to a decrease in crude oil production from 25,258 barrels in the first nine
months of 2000 to 5,177 barrels in the first nine months of 2001. Gas revenues
decreased from $1,567,877 in the first nine months of 2000 to $807,238 in the
first nine months of 2001, primarily due to a decrease in gas volumes from
553,844 Mcf in the first nine months of 2000 to 131,287 Mcf in the first nine
months of 2001. The decrease in gas revenues was partially offset by an increase
in the average natural gas sales price from $2.83 per Mcf in the first nine
months of 2000 to $6.15 per Mcf in the first nine months of 2001. Capital
expenditures for the first nine months of 2001 decreased by $149,381 from the
first nine months of 2000 primarily due to year 2000 capital projects. Operating
expenses in the first nine months of 2001 decreased by $770 from the first nine
months of 2000.

                                       13
<Page>
FUTURE NET REVENUES AND TERMINATION OF THE TRUST

    Based on a reserve study provided to the Trust by DeGolyer and MacNaughton,
independent petroleum engineers, it was estimated that as of October 31, 2000
future net revenues attributable to the Trust's royalty interests approximated
$28.7 million. Such reserve study also indicates that approximately 75% of the
future net revenues from the Royalty Properties are expected to be received by
the Trust during the next three years. In addition, because the Trust will
terminate in the event estimated future net revenues fall below $2 million, it
would be possible for the Trust to terminate even though some or all of the
Royalty Properties continued to have remaining productive lives. Upon
termination of the Trust, the Trustees will sell for cash all of the assets held
in the Trust estate and make a final distribution to Unit holders of any funds
remaining after all Trust liabilities have been satisfied. The estimates of
future net revenues discussed above are subject to large variances from year to
year and should not be construed as exact. There are numerous uncertainties
present in estimating future net revenues for the Royalty Properties. The
estimate may vary depending on changes in market prices for crude oil and
natural gas, the recoverable reserves, annual production and costs assumed by
DeGolyer and MacNaughton. In addition, future economic and operating conditions
as well as results of future drilling plans may cause significant changes in
such estimate. The discussion set forth above is qualified in its entirety by
reference to the Trust's 2000 Annual Report on Form 10-K. The Form 10-K is
available upon request from the Corporate Trustee.

SPECIAL COST ESCROW ACCOUNT

    The Conveyance provides for reserving funds for estimated future "Special
Costs" of plugging and abandoning wells, dismantling platforms and other costs
of abandoning the Royalty Properties, as well as for the estimated amount of
future drilling projects and other capital expenditures on the Royalty
Properties. As provided in the Conveyance, the amount of funds to be reserved is
determined based on factors including estimates of aggregate future production
costs, aggregate future Special Costs, aggregate future net revenues and actual
current net proceeds. Deposits into this account reduce current distributions
and are placed in an escrow account and invested in short-term certificates of
deposit. Such account is herein referred to as the "Special Cost Escrow
Account." The Trust's share of interest generated from the Special Cost Escrow
Account serves to reduce the Trust's share of allocated production costs.
Special Cost Escrow funds will generally be utilized to pay Special Costs to the
extent there are not adequate current net proceeds to pay such costs. Special
Costs that have been paid are no longer included in the Special Cost Escrow
calculation. Deposits to the Special Cost Escrow Account will generally be made
when the balance in the Special Cost Escrow Account is less than 125% of future
Special Costs and there is a Net Revenues Shortfall (a calculation of the excess
of estimated future costs over estimated future net revenues pursuant to a
formula contained in the Conveyance). When there is not a Net Revenues
Shortfall, amounts in the Special Cost Escrow Account will generally be
released, to the extent that Special Costs have been incurred. Amounts in the
Special Cost Escrow Account generally will also be released when the balance in
such account exceeds 125% of future Special Costs. In the first nine months of
2000, there was a deposit of approximately $778,327 into the Special Cost Escrow
Account. The deposit was primarily a result of an increase in the Working
Interest Owners' current estimate of projected capital expenditures on the
Royalty Properties. In the first nine months of 2001, there was a net deposit of
funds into the Special Cost Escrow Account. The Trust's share of the funds
deposited was approximately $315,509. The deposit was primarily a result of an
increase in the Working Interest Owners' current estimate of projected capital
expenditures of

                                       14
<Page>
the Royalty Properties. As of September 30, 2001, approximately $5,712,345
remained in the Special Cost Escrow Account.

    Chevron, in its capacity as Managing General Partner, has advised the Trust
that additional deposits to the Special Cost Escrow Account may be required in
future periods in connection with other production costs, other abandonment
costs, other capital expenditures and changes in the estimates and factors
described above. Such deposits, if made, could result in a significant reduction
in Royalty income in the periods in which such deposits are made, including the
possibility that no Royalty income would be received in such periods.

OVERVIEW OF PRODUCTION, PRICES AND NET PROCEEDS

    The following schedule provides a summary of the volumes and weighted
average prices for crude oil and condensate and natural gas recorded by the
Working Interest Owners for the Royalty Properties, as well as the Working
Interest Owners' calculations of the net proceeds and the royalties paid to the
Trust during the periods indicated. Net proceeds due to the Trust are calculated
for each three month period commencing on the first day of February, May, August
and November.

<Table>
<Caption>
                                                                   ROYALTY PROPERTIES
                                                                   THREE MONTHS ENDED
                                                                    SEPTEMBER 30,(1)
                                                              ----------------------------
                                                                   2001           2000
                                                              --------------   -----------
<S>                                                           <C>              <C>
Crude oil and condensate (bbls).............................         164,624       196,673
Natural gas and gas products (Mcf)..........................         418,036       841,699
Crude oil and condensate average price, per bbl.............  $        26.40   $     27.92
Natural gas average price, per Mcf (excluding gas
  products).................................................  $         3.71   $      4.00
Crude oil and condensate revenues...........................  $    4,345,468   $ 5,490,663
Natural gas and gas products revenues.......................       1,521,066     3,262,120
Production expenses.........................................        (935,540)     (908,310)
Capital expenditures........................................        (858,609)     (355,194)
Undistributed Net Loss (Income)(2)..........................         (28,535)      (63,367)
(Provision for) Refund of escrowed special costs............          83,867       524,956
                                                              --------------   -----------
NET PROCEEDS................................................       4,127,717     7,950,868
Royalty interest............................................            x25%          x25%
                                                              --------------   -----------
Partnership share...........................................       1,031,929     1,987,717
Trust interest..............................................         x99.99%       x99.99%
                                                              --------------   -----------
Trust share.................................................  $    1,031,826   $ 1,987,518
                                                              ==============   ===========
</Table>

---------

(1) The amounts for the three months ended September 30, 2001 and 2000 represent
    actual production for the periods May 2001 through July 2001, and May 2000
    through July 2000, respectively.

(2) Undistributed net loss represents negative Net Proceeds generated during the
    respective period. An undistributed net loss is carried forward and offset,
    in future periods, by positive Net Proceeds earned by the related Working
    Interest Owner(s). Undistributed net income represents positive Net
    Proceeds, generated during the respective period, that were applied to an
    existing loss carryforward. As of September 30, 2001, the loss carryforward
    was $424,588 ($106,147 net to the Trust).

                                       15
<Page>

<Table>
<Caption>
                                                                 ROYALTY PROPERTIES
                                                                  NINE MONTHS ENDED
                                                                  SEPTEMBER 30,(1)
                                                              -------------------------
                                                                 2001          2000
                                                              -----------   -----------
<S>                                                           <C>           <C>
Crude oil and condensate (bbls).............................      484,985       629,699
Natural gas and gas products (Mcf)..........................    1,509,357     3,196,563
Crude oil and condensate average price, per bbl.............  $     29.11   $     27.05
Natural gas average price, per Mcf (excluding gas
  products).................................................  $      5.88   $      2.98
Crude oil and condensate revenues...........................  $14,118,523   $17,033,945
Natural gas and gas products revenues.......................    8,656,304     9,379,270
Production expenses.........................................   (2,962,413)   (3,343,155)
Capital expenditures........................................   (1,960,265)   (1,464,915)
Undistributed Net Loss (Income)(2)..........................     (369,840)     (242,874)
(Provision for) Refund of escrowed special costs............   (1,513,636)   (3,113,307)
                                                              -----------   -----------
NET PROCEEDS................................................   15,968,672    18,248,964
Royalty interest............................................         x25%          x25%
                                                              -----------   -----------
Partnership share...........................................    3,992,168     4,562,241
Trust interest..............................................      x99.99%       x99.99%
                                                              -----------   -----------
Trust share.................................................  $ 3,991,769   $ 4,561,785
                                                              ===========   ===========
</Table>

---------

(1) The amounts for the nine months ended September 30, 2001 and 2000 represent
    actual production for the periods November 2000 through July 2001, and
    November 1999 through July 2000, respectively.

(2) Undistributed net loss represents negative Net Proceeds generated during the
    respective period. An undistributed net loss is carried forward and offset,
    in future periods, by positive Net Proceeds earned by the related Working
    Interest Owner(s). Undistributed net income represents positive Net
    Proceeds, generated during the respective period, that were applied to an
    existing loss carryforward. As of September 30, 2001, the loss carryforward
    was $424,588 ($106,147 net to the Trust).

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

    Reference is made to Item 1 of this Form 10-Q.

                                       16
<Page>
                           PART II--OTHER INFORMATION

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.

(A) EXHIBITS

    (Asterisk indicates exhibit previously filed with the Securities and
Exchange Commission and incorporated herein by reference. JPMorgan Chase Bank
("Corporate Trustee"), formerly known as The Chase Manhattan Bank which was
formerly known as Chase Bank of Texas, National Association, which was formerly
known as Texas Commerce Bank, National Association.

<Table>
<Caption>
                                                                                          SEC FILE OR
                                                                                          REGISTRATION   EXHIBIT
                                                                                             NUMBER       NUMBER
                                                                                          ------------   --------
    <S>                     <C>                                                           <C>            <C>
    4(a)*                   --Trust Agreement dated as of January 1, 1983, among Tenneco
                              Offshore Company, Inc., Texas Commerce Bank National
                              Association, as corporate trustee, and Horace C. Bailey,
                              Joseph C. Broadus and F. Arnold Daum, as individual
                              trustees (Exhibit 4(a) to Form 10-K for the year ended
                              December 31, 1992 of TEL Offshore Trust)..................     0-6910          4(a)
    4(b)*                   --Agreement of General Partnership of TEL Offshore Trust
                              Partnership between Tenneco Oil Company and the TEL
                              Offshore Trust, dated January 1, 1983 (Exhibit 4(b) to
                              Form 10-K for year ended December 31, 1992 of TEL Offshore
                              Trust)....................................................     0-6910          4(b)
    4(c)*                   --Conveyance of Overriding Royalty Interests from
                              Exploration I to the Partnership (Exhibit 4(c) to
                              Form 10-K for year ended December 31, 1992 of TEL Offshore
                              Trust)....................................................     0-6910          4(c)
    4(d)*                   --Amendments to TEL Offshore Trust Trust Agreement, dated
                              December 7, 1984 (Exhibit 4(d) to Form 10-K for year ended
                              December 31, 1992 of TEL Offshore Trust)..................     0-6910          4(d)
    4(e)*                   --Amendment to the Agreement of General Partnership of TEL
                              Offshore Trust Partnership, effective as of January 1,
                              1983 (Exhibit 4(e) to Form 10-K for year ended
                              December 31, 1992 of TEL Offshore Trust)..................     0-6910          4(e)
    10(a)*                  --Purchase Agreement, dated as of December 7, 1984 by and
                              between Tenneco Oil Company and Tenneco Offshore II
                              Company (Exhibit 10(a) to Form 10-K for year ended
                              December 31, 1992, of TEL Offshore Trust).................     0-6910         10(a)
    10(b)*                  --Consent Agreement, dated November 16, 1988, between TEL
                              Offshore Trust and Tenneco Oil Company (Exhibit 10(b) to
                              Form 10-K for year ended December 31, 1988 of TEL Offshore
                              Trust)....................................................     0-6910         10(b)
    10(c)*                  --Assignment and Assumption Agreement, dated November 17,
                              1988, between Tenneco Oil Company and TOC-Gulf of
                              Mexico Inc. (Exhibit 10(c) to Form 10-K for year ended
                              December 31, 1988 of TEL Offshore Trust)..................     0-6910         10(c)
    10(d)*                  --Gas Purchase and Sales Agreement Effective September 1,
                              1993 between Tennessee Gas Pipeline Company and Chevron
                              U.S.A. Production Company (Exhibit 10(d) to Form 10-K for
                              year ended December 31, 1993 of TEL Offshore Trust).......     0-6910         10(d)
</Table>

(B)  REPORTS ON FORM 8-K

    No reports on Form 8-K were filed with the Securities and Exchange
Commission during the third quarter of 2001.

                                       17
<Page>
                                   SIGNATURES

    Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.

<Table>
<S>                                         <C>        <C>
                                            TEL OFFSHORE TRUST

                                            By:        JPMorgan Chase Bank, Corporate Trustee

                                            By:                     /s/ MIKE ULRICH
                                                       -----------------------------------------
                                                                      MIKE ULRICH
                                                                     VICE PRESIDENT
                                                                   AND TRUST OFFICER
</Table>

Date: November 14, 2001

The Registrant, TEL Offshore Trust, has no principal executive officer,
principal financial officer, board of directors or persons performing similar
functions. Accordingly, no additional signatures are available and none have
been provided.

                                       18
<Page>
                                      TEL
                                    OFFSHORE
                                     TRUST
                               FEDERAL INCOME TAX
                                  INFORMATION
                                      2001
<Page>
                               TEL OFFSHORE TRUST
                                 EIN 76-6004064
                                   SCHEDULE B
                              SECOND QUARTER 2000
                            TAX INFORMATION PER UNIT
                               (4,751,510 UNITS)

<Table>
<Caption>
                                         PARTNERSHIP
                                        ITEMS PER UNIT                   TRUST ITEMS PER UNIT
                                  --------------------------   -----------------------------------------
                                              DEPLETION AS A                                **(INCREASE)
                                   ROYALTY      PERCENT OF     INTEREST    ADMINISTRATIVE   DECREASE IN
          RECORD DATE              INCOME     ROYALTY BASIS     INCOME        EXPENSE         RESERVE
          -----------             ---------   --------------   ---------   --------------   ------------
<S>                               <C>         <C>              <C>         <C>              <C>
March 31, 2001..................  $0.319613       5.2875%      $0.007768     $0.020427       $ 0.029151
June 30, 2001...................  $0.303335       5.0182%       0.002208      0.028092         0.000000
September 30, 2001..............   0.217179       3.5929%       0.006484      0.014909        (0.000000)
December 29, 2001...............   0.000000       0.0000%       0.000000      0.000000         0.000000
                                  ---------      --------      ---------     ---------       ----------
Year to date....................  $0.840127      13.8986%      $0.016460     $0.063428       $ 0.029151
                                  =========      ========      =========     =========       ==========
</Table>

                           SUMMARY OF TAXABLE INCOME

<Table>
<Caption>
                                                               PER UNIT
                                                              ----------
<S>                                                           <C>
Royalty Income..............................................  $ 0.840127
Interest Income.............................................    0.016460
Depletion Deduction.........................................   (0.010320)
Administrative Expense Deduction............................   (0.063428)
(Increase)/Decrease in Reserve..............................    0.029151
                                                              ----------
Net Amount..................................................  $ 0.811991
                                                              ==========
</Table>

**  Increase or decrease in the reserve amount has no tax effect and is shown
    for information purposes only.
<Page>
                        TAX BASIS OF UNITS AND ROYALTY*

<Table>
<S>                                                           <C>
Basis Assigned to TEL Offshore Trust Units--1/1/83..........  $ 6.750000
Basis Allocated to Offshore II Company (Sold December 17,
  1984).....................................................   (0.120000)
                                                              ----------
Royalty Basis 1/1/83........................................    6.630000
Depletion Year 1983.........................................   (0.769366)
                                                              ----------
Royalty Basis 1/1/84........................................    5.860634
Depletion Year 1984.........................................   (1.203489)
                                                              ----------
Royalty Basis 1/1/85........................................    4.657145
Depletion Year 1985.........................................   (1.126563)
                                                              ----------
Royalty Basis 1/1/86........................................    3.530582
Depletion Year 1986.........................................   (0.555675)
                                                              ----------
Royalty Basis 1/1/87........................................    2.974907
Depletion Year 1987.........................................   (1.424231)
                                                              ----------
Royalty Basis 1/1/88........................................    1.550676
Depletion Year 1988.........................................   (0.384321)
                                                              ----------
Royalty Basis 1/1/89........................................    1.166355
Depletion Year 1989.........................................   (0.241515)
                                                              ----------
Royalty Basis 1/1/90........................................    0.924840
Depletion Year 1990.........................................   (0.242097)
                                                              ----------
Royalty Basis 1/1/91........................................    0.682743
Depletion Year 1991.........................................   (0.092228)
                                                              ----------
Royalty Basis 1/1/92........................................    0.590515
Depletion Year 1992.........................................   (0.058181)
                                                              ----------
Royalty Basis 1/1/93........................................    0.532334
Depletion Year 1993.........................................   (0.079729)
                                                              ----------
Royalty Basis 1/1/94........................................    0.452605
Depletion Year 1994.........................................   (0.148288)
                                                              ----------
Royalty Basis 1/1/95........................................    0.304317
Depletion Year 1995.........................................   (0.064972)
                                                              ----------
Royalty Basis 1/1/96........................................    0.239345
Depletion Year 1996.........................................   (0.024448)
                                                              ----------
Royalty Basis 1/1/97........................................    0.214897
Depletion Year 1997.........................................   (0.048705)
                                                              ----------
Royalty Basis 1/1/98........................................    0.166192
Depletion Year 1998.........................................   (0.031658)
                                                              ----------
Royalty Basis 1/1/99........................................    0.134534
Depletion Year 1999.........................................    (.024322)
                                                              ----------
Royalty Basis 1/1/00........................................    0.110212
Depletion Year 2000.........................................   (0.035962)
                                                              ----------
Royalty Basis 1/1/01........................................    0.074250
Depletion Through Third Quarter 2001........................    0.010320
                                                              ----------
Royalty Basis 9/30/2001.....................................  $ 0.063930
                                                              ==========
</Table>

------------

*   For Unit holders who acquired their Units in the initial distribution in
    January of 1983.

    For Unit holders acquiring Units other than in the initial distribution from
    Tenneco Offshore Company and prior to December 17, 1984, their royalty basis
    should be equal to 98.2533% of the purchase price of such Units, less
    depletion taken from the date of purchase.

    Unit holders who acquired their Units after December 17, 1984 will have a
    basis in the royalty equal to the purchase price of such Units, less
    depletion taken from the date of purchase.